Well bore servicing fluids comprising thermally activated viscosification compounds and methods of using the same

ABSTRACT

Well bore servicing fluids are provided that include a thermally activated viscosification compound. Further, methods of servicing a well bore are provided that include displacing such a servicing fluid into the well bore, wherein a viscosity of the servicing fluid increases as it passes down the well bore due to its temperature increasing. Thus, the viscosity of the servicing fluid is effective to suspend solids therein when the servicing fluid is in the well bore. The servicing fluid may be, for example, a cement slurry, a drilling fluid, a gravel packing fluid, a fracturing fluid, a completion fluid, or a work-over fluid. In an embodiment, the thermally activated viscosification compound includes at least one water-soluble hydrophobically modified polymer comprising a hydrophobic substituent having from about 1 to about 22 carbon atoms.

FIELD OF THE INVENTION

This invention generally relates to well bore servicing fluids andmethods of servicing a well bore. More specifically, the inventionrelates to methods of servicing a well bore using a servicing fluidcomprising a thermally activated viscosification compound for promotingthe suspension of particles in the servicing fluid.

BACKGROUND OF THE INVENTION

Natural resources such as gas, oil, and water residing in a subterraneanformation can be recovered using well-known techniques. The steps takento prepare for the recovery of such resources usually require the use ofvarious fluids. For example, drilling fluids or muds are typicallycirculated through well bores as they are drilled into the formation.During the drilling process, the drill bit generates drill cuttings thatconsist of small pieces of shale and rock. The drilling fluid carriesthe drill cuttings in a return flow stream back to the well drillingplatform. After terminating the circulation of the drilling fluid, astring of pipe, e.g., casing, is run in the well bore. The drillingfluid is then usually circulated downwardly through the interior of thepipe and upwardly through the annulus, which is located between theexterior of the pipe and the walls of the well bore.

Another fluid known as a gravel packing fluid having a relatively largegrained sand, i.e., gravel, suspended therein also may be utilized toprevent migration of smaller grained sand from the subterraneanformation into the well bore and to maintain the integrity of theformation. In particular, a permeable screen may be placed against theface of the subterranean formation, followed by pumping the gravelpacking fluid into the annulus of the well bore such that gravel becomespacked against the exterior of the screen. In addition, a cement slurrymay be pumped into the well bore during a primary cementing process inwhich the cement slurry is placed in the annulus of the well bore andpermitted to set into a hard mass (i.e., sheath) to thereby attach thestring of pipe to the walls of the well bore and seal the annulus.Subsequent secondary cementing operations, e.g., completion and workover operations, may also be performed using cement slurries.

Yet another fluid, i.e., a fracturing fluid, is typically used tofracture the subterranean formation. The fracturing fluid is pumped intothe well bore at a rate and a pressure sufficient to form fractures thatextend into the subterranean formation, providing additional pathwaysthrough which fluids being produced can flow into the well bores. Thefracturing fluid is usually a water-based fluid containing a gellingagent, i.e., a polymeric material that absorbs water and forms a gel asit undergoes hydration. The gelling agent serves to increase theviscosity of the fracturing fluid. The fracturing fluid also typicallyincludes particulate matter known as a proppant, e.g., graded sand,bauxite, or resin coated sand, may be suspended in the fracturing fluid.The proppant becomes deposited into the fractures and thus holds thefractures open after the pressure exerted on the fracturing fluid hasbeen released.

The viscosities of conventional fluids used in a well bore usuallydecrease with increasing temperatures. As such, the fluids undesirablyundergo thermal thinning as they pass down the well bore where they areexposed to increasing temperatures. Viscosification agents such asgelling agents may be added to the fluids to increase their viscosities.However, the resulting fluids are very viscous at the earth's surfaceand thus require relatively high pump pressures to be conveyed downhole.In addition, they also experience thermal thinning as they pass down thewell bore.

Unfortunately, the thermal thinning of fluids as they pass down the wellbore typically leads to various problems, depending on the type of fluidinvolved. For example, the drilling fluid may be unable to suspend drillcuttings therein as it flows back to the surface. Thus, the drillcuttings may settle out of the drilling fluid and become deposited inundesired locations in the well bore. Furthermore, those fluidscontaining particles such as the cement slurry, the gravel packingfluid, and the fracturing fluid may experience settling of the particlesas the fluids are pumped down the well bore. As a result, the particlesare not transported to their proper locations in the well bore. Further,in the absence of such particles, the density of the fluids may drop toa level at which they are incapable of withstanding relatively highfluid pressures downhole, particularly in the case of a high densitycement slurry. A need therefore exists for maintaining the viscosity offluids as they are passed into a well bore so as to prevent the settlingof materials in those fluids.

SUMMARY OF THE INVENTION

Well bore servicing fluids include a thermally activated viscosificationcompound. Further, methods of servicing a well bore include displacingsuch a servicing fluid into the well bore, wherein a viscosity of theservicing fluid increases as it passes down the well bore due to itstemperature increasing. Thus, the viscosity of the servicing fluid iseffective to suspend solids therein when the servicing fluid is in thewell bore. The servicing fluid may be, for example, a cement slurry, adrilling fluid, a gravel packing fluid, a fracturing fluid, a completionfluid, or a work-over fluid. In an embodiment, the thermally activatedviscosification compound includes at least one water-solublehydrophobically modified polymer comprising a hydrophobic substituenthaving from about 1 to about 22 carbon atoms. The hydrophobicallymodified polymer may be non-ionic or ionic. When the hydrophobicallymodified polymer is non-ionic, the servicing fluid may or may notinclude an ionic surfactant, an inorganic ion, or combinations thereof.When the hydrophobically modified polymer is ionic, the servicing fluidmay or may not comprise a non-ionic surfactant, an inorganic ion, orcombinations thereof.

DESCRIPTION OF THE DRAWINGS

The invention, together with further advantages thereof, may best beunderstood by reference to the following description taken inconjunction with the accompanying drawing in which:

FIG. 1 depicts the viscosity of an aqueous solution containing athermoreversible acrylic polymer as a function of temperature.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In accordance with an embodiment, servicing fluids for servicing a wellbore comprise a thermally activated viscosification compound. As usedherein, a “servicing fluid” refers to a fluid used to drill, complete,work over, fracture, or in any way prepare a well bore for the recoveryof materials residing in a subterranean formation penetrated by the wellbore. It is understood that “subterranean formation” encompasses bothareas below exposed earth or areas below earth covered by water such assea or ocean water. As used herein, a “thermally activatedviscosification compound” refers to a compound that causes the viscosityof a fluid in which it is contained to increase as the temperature ofthe fluid increases and optionally decrease as the temperature of thefluid decreases. As such, the viscosity of the servicing fluid iseffective to suspend solids in the fluid as it is being passed down awell bore, particularly a high temperature or geothermal well bore.Further, when the fluid containing the thermally activatedviscosification compound is near the surface of the earth, its viscosityis sufficiently low such that the pump pressure required to pump it intothe well bore is relatively low.

Examples of servicing fluids include, but are not limited to, a drillingfluid or mud, a cement slurry, a gravel packing fluid, a fracturingfluid, a completion fluid, and a work-over fluid, all of which are wellknown in the art. The servicing fluid is preferably an aqueous fluid,and it may comprise components other than the thermally activatedviscosification compound. As would be apparent to one skilled in theart, these components may vary depending on the intended use of theservicing fluid. The thermally activated viscosification compound andthese other components may be combined with the servicing fluid in anyorder deemed appropriate by one skilled in the art.

The thermally activated viscosification compound may comprise, forexample, at least one chemically crosslinked gel-forming compound, atleast one physically crosslinked gel-forming compound, or combinationsthereof. A chemically crosslinked gel refers to a gel in which anadditional, smaller molecule is chemically bonded between at least twocrosslinked polymer chains, wherein the gel is usually thermallyirreversible, i.e., its formation cannot be reversed by changing itstemperature; however, the swelling of the gel by the absorption ofaqueous fluids can be reversible with temperature changes. A physicallycrosslinked gel refers to a gel having a transient bond or complexbetween at least two non-crosslinked polymer chains without the use ofadditional, smaller molecules, wherein the gel is usually thermallyreversible and the transient bond, which is typically present inpolymers containing hydrophobic groups, can be dissociated with changesin shear or temperature. In a preferred embodiment, the thermallyactivated viscosification compound comprises a linear polymer that iscapable of forming a thermally reversible gel, preferably a physicallycrosslinked gel. The specific concentration of the thermally activatedviscosification compound in the servicing fluid depends upon theintended use of the fluid. In an embodiment, the servicing fluidcomprises from about 0.1% to about 5% of the thermally activatedviscosification compound by total weight of the servicing fluid.

In an embodiment, the thermally activated viscosification compoundincludes at least one water-soluble hydrophobically modified polymer,wherein the hydrophobic substituent has from about 1 to about 22 carbonatoms. The thermally activated viscosification compound may comprise anon-ionic water-soluble hydrophobically modified polymer, an ionicwater-soluble hydrophobically modified polymer, or combinations thereof.When the thermally activated viscosification compound comprises anon-ionic hydrophobically modified polymer, the servicing fluid may ormay not comprise an ionic surfactant, an inorganic salt, or combinationsthereof, depending on the particular polymer being used. In the casewhere the thermally activated viscosification compound comprises anionic hydrophobically modified polymer, the servicing fluid might ormight not comprise a non-ionic surfactant, an inorganic salt, orcombinations thereof, depending on the particular polymer being used.

Examples of non-ionic water-soluble hydrophobically modified polymerscapable of forming gels without ionic surfactants or inorganic saltsinclude alkyl hydroxyl alkylcellulose, methyl cellulose ethers, andhydroxypropyl methyl cellulose ethers, which are used either singly orin combination with one or more starches. Suitable methyl celluloseethers and hydroxypropyl methyl cellulose ethers are commerciallyavailable from Dow Chemical Company under the trade name METHOCELpolymers. Other examples of non-ionic water-soluble hydrophobicallymodified polymers capable of forming gels without ionic surfactants orinorganic salts include the following: copolymers of N-alkylacrylamidesand hydrophilic comonomers as described in U.S. Pat. No. 5,104,954 andin Varghese et al., “Designing New Thermoreversible Gels by MolecularTailoring of Hydrophilic-Hydrophobic Interactions”, 112 J. ChemicalPhysics (USA), p. 3063-3070 (2000), each of which is incorporated byreference herein in its entirety; copolymers of N,N-dimethylacrylamidesand alkoxyalkyl or alkyl acrylates as described in U.S. Pat. No.5,104,954, which is incorporated by reference herein in its entirety;ethyleneoxide-propyleneoxide-ethyleneoxide tri-block polymerscommercially available from BASF Corporation of Mount Olive, N.J. underthe tradename PLURONICS polymers; and poly(ethyleneglycol-(DL-lacticacid)-ethyleneglycol) triblock copolymers.

Examples of non-ionic water-soluble hydrophobically modified polymerscapable of forming gels when used in combination with an ionicsurfactant include ethyl hydroxyethyl-, methyl-, hydroxypropyl-, andlong alkyl group modified cellulose ethers combined with anionicsurfactants such as sodium dodecyl sulfate or cationic surfactants suchas cetyltrimethylammonium bromide. A suitable commercially availableethyl hydroxyethyl cellulose ether is BERMOCOLL CST-103 polymer sold byAkzo Nobel Corporation of Switzerland. Examples of non-ionicwater-soluble hydrophobically modified polymers capable of forming gelswhen used in combination with an inorganic metal ion includehydroxypropyl ethers of cellulose combined with borax as described inIde et al., “Thermoreversible Hydrogel of Short ChainO-(2,3-Dihydroxypropyl)cellulose/Borax Aqueous Solution. Microscopic vsMacroscopic Properties,” 31 Macromolecules, p. 8878-8885, (1998), whichis incorporated by reference herein in its entirety.

Examples of ionic water-soluble hydrophobically modified polymerscapable of forming gels without non-ionic surfactants or inorganic saltsinclude: copolymers of stearylacrylate and acrylic acid; terpolymers ofN-isopropylacrylamide, trimehyl acrylamidopropyl ammonium iodide, and3-dimethyl-(methacryloxyethyl) ammonium propane sulfonate; copolymers ofN-tertiarybutylacrylamide or N-isopropylacrylamide and2-acrylamide-2-methyl propane sulfonic acid; andpoly(ethyleneoxide)-block-poly-(propyleneoxide)-block-poly(ethyleneoxide)grafted with polysodium acrylate. Additionally, further examples ofionic water-soluble hydrophobically modified polymers include copolymersof N-alkylacrylamides and ionic monomers as described in U.S. Pat. No.5,432,245. Particularly. U.S. Pat. No. 5,432,245 provides that itshydrophobically modified polymers are represented by the general formula“-(A)_(x),-(B)_(y)-”, wherein A can range from 40-99.9 mole percent ofrecurring units derived from one or more hydrophobic N-substitutedacrylamide or methacrylamide monomers and B can range from 60-0.1 molepercent of recurring units of one or more ionic hydrophilic monomers,U.S. Pat. No. 5,432,245 incorporated by reference herein in itsentirety.

An example of an ionic water-soluble hydrophobically modified polymercapable of forming a gel when used in combination with a nonionicsurfactant includes hydrophobically modified poly(sodium acrylate)combined with an oligoethylene glycol monodecyl ether surfactant. Anexample of an ionic water-soluble hydrophobically modified polymercapable of forming a gel when used in combination with an inorganicmetal ion includes a copolymer of N-vinylcaprolactam and sodium acrylatecombined with a calcium salt as described in Peng et al., “Ca²⁺InducedThermoreversible and Controllable Complexation ofPoly(N-vinylcaprolactam-co-sodium acrylate) Microgels in Water,” 105 J.Phys. Chem. B, p 2331-2335 (2001), which is incorporated by referenceherein in its entirety. It is understood that any combinations of theforegoing examples of ionic and non-ionic hydrophobically modifiedpolymers may be used in the well bore servicing fluid.

In an embodiment, the well bore servicing fluid is an aqueous fluid thatoptionally comprises an encapsulated salt capable of being releaseddownhole for reducing a temperature of the servicing fluid and therebyreducing a viscosity of the servicing fluid. The encapsulated salt canendothermically dissolve in the water of the servicing fluid upon itsrelease. Examples of such salts include ammonium salts such as ammoniumchloride and ammonium nitrate, sodium salts such as sodium chloride,sodium nitrite, and sodium nitrate, and potassium salts such aspotassium chloride, potassium nitrite, potassium nitrate, and potassiumpermanganate. An example of a method of encapsulation is described inU.S. Pat. No. 6,554,071, which is incorporated by reference herein inits entirety. Additional details regarding the use of the encapsulatedsalt in the servicing fluid are described later.

According to another embodiment, methods of using a previously describedservicing fluid comprising a thermally activated viscosificationcompound to service a well bore include displacing the fluid into thewell bore so that it may be used for its intended purpose. Due to thepresence of the thermally activated viscosification compound, theservicing fluid does not undergo thermal thinning but instead increasesin viscosity as it passes down the well bore as a result of itstemperature increasing. That is, the thermally activated viscosificationcompound forms a gel, preferably a thermally reversible gel, as itpasses down the well bore. The viscosity of the servicing fluid iseffective to suspend solids therein when the servicing fluid is in thewell bore where it is subjected to relatively high temperatures. Thus,there is no need to be concerned that solids contained in the servicingfluid, e.g., cement particles in a cement slurry, sand or gravelparticles in a gravel packing fluid, or proppant in a fracturing fluid,will settle before the fluid has been used to perform its intendedpurpose. In addition, the viscosity of the servicing fluid at atemperature near the surface of the earth (e.g., about room temperature)is low enough to require relatively low pump pressures for conveyancedownhole.

In an embodiment, the servicing fluid is used as an aqueous fracturingfluid that contains at least one encapsulated salt and at least onethermally activated viscosification compound capable of forming aphysically crosslinked, thermally reversible gel, wherein examples ofsuitable encapsulated salts and thermally activated viscosificationcompounds are provided above. The servicing fluid may be pumped into thewell bore at a pressure sufficient to fracture the subterraneanformation. As the servicing fluid passes down the well bore, the saltremains encapsulated such that it does not contact the fluid. In themanner described above, the viscosity of the fluid increases as itpasses downhole, ensuring that the fluid is viscous enough to fracturethe subterranean formation and to carry a proppant to the formation.Then the encapsulated salt is strategically released after thefracturing has occurred and the proppant has been deposited in thesubterranean formation. The release of the salt may result from theabsorption of water by the coating surrounding the encapsulated salt,which causes the coating to swell. The water of the servicing fluid isthus allowed to enter the interior of the encapsulated salt where itendothermically dissolves the salt and becomes released into the wellbore. Due to the endothermic dissolution of the salt, the temperature ofthe servicing fluid decreases. As a result of this temperature decrease,the viscosity of the servicing fluid decreases, allowing the fluid to bemore efficiently flowed back to the surface of the earth with lessformation damage.

In another embodiment, the servicing fluid is used as a drilling fluidthat contains a thermally activated viscosification compound capable offorming a physically crosslinked, thermally reversible gel. In thiscase, a well bore is drilled while circulating the servicing fluid intothe well bore and back to the surface, resulting in the formation ofdrill cuttings. The servicing fluid in the well bore is relatively hotand viscous and thus has a viscosity effective to suspend and carry thedrill cuttings back to the surface. The drilling fluid can be collectedin tanks near the surface to allow the fluid to cool such that itsviscosity drops, resulting in the settling of the drill cuttings. Thosedrill cuttings then can be separated from the drilling fluid usingconventional techniques such as subjecting the mixture to vibrationswith shale shakers, centrifugation, or dilution with water. This methodprovides for prolonged maintenance of the properties of the drillingfluid without having to replenish its components such that the fluid canbe reused multiple times.

EXAMPLES

The invention having been generally described, the following examplesare given as particular embodiments of the invention and to demonstratethe practice and advantages hereof. It is understood that the examplesare given by way of illustration and are not intended to limit thespecification or the claims to follow in any manner.

Example 1

An aqueous solution containing 2% thermoreversible acrylic polymer byweight of the solution was placed in a 50 mL graduated cylinder. Thecylinder containing the polymer solution was then placed in a mineraloil heating bath. A No. 3 spindle was attached to a BROOKFIELDviscometer (model DV-II+) manufactured by Brookfield Engineering LabInc. of Middleboro, Mass., and the spindle was immersed in the polymersolution. The mineral oil was heated a few degrees at a time whilemeasuring the viscosity of the polymer solution. After reaching themaximum temperature, the temperature was decreased at a rate of a fewdegrees per minutes. Table 1 below shows the average viscosity of thepolymer solution for each temperature interval. In addition, FIG. 1depicts the viscosity of the polymer solution as a function oftemperature.

TABLE 1 Temperature Rang, ° F. Average Viscosity, centipoise 77-96 2,260 97-100 1,750 101-118 1,300 119-165 900 166-180 1,400 181-160 2,900161-130 1,500 131-108 1,150 107-77  2,500As shown in Table 1 and in FIG. 1, the polymer solution initiallybehaved as a typical polymer in water that experiences thermal thinningin response to an increase in temperature. In particular, the viscosityof the polymer solution decreased as it was heated from 77° F. to 165°F. Then, surprisingly, as the polymer solution was heated from 166° F.to 180° F., its viscosity began to rise. Then its viscosity rose evenmore as it was cooled from 181° F. to 160° F. Subsequent cooling of thepolymer solution caused its viscosity to drop and then to rise again.These results show that the thermoreversible acrylic polymer forms areversible gel upon heating and can serve as a thermally activatedviscosification compound in a well bore servicing fluid.

Example 2

The polymer solution in Example 1 was diluted such that the amount ofthe thermoreversible acrylic polymer present in the solution was 1% byweight of the solution. Moreover, sodium chloride in an amount of 1% byweight of the polymer solution was added to the solution. The viscosityof the resulting polymer solution was measured as described inExample 1. The results are shown in Table 2 below.

TABLE 2 Temperature Range,° F. Average Viscosity, Centipoise 78-99 128100-118 210 119-170 85 169-100 43 99-84 380 84-77 250The results in Table 2 suggest that the thermoreversible acrylic polymerand an ionic compound can be used in combination to form a solution thatviscosifies reversibly with temperature in certain temperature ranges.Thus, the polymer can serve as a thermally activated viscosificationcompound in a well bore servicing fluid. The results also show that theviscosification temperature range may or may not be identical duringheating and cooling cycles or vice versa.

While preferred embodiments of the invention have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit and teachings of the invention. Theembodiments described herein are exemplary only, and are not intended tobe limiting. Many variations and modifications of the inventiondisclosed herein are possible and are within the scope of the invention.Use of the term “optionally” with respect to any element of a claim isintended to mean that the subject element is required, or alternatively,is not required. Both alternatives are intended to be within the scopeof the claim.

Accordingly, the scope of protection is not limited by the descriptionset out above but is only limited by the claims which follow, that scopeincluding all equivalents of the subject matter of the claims. Each andevery claim is incorporated into the specification as an embodiment ofthe present invention. Thus, the claims are a further description andare an addition to the preferred embodiments of the present invention.The discussion of a reference in the Description of Related Art is notan admission that it is prior art to the present invention, especiallyany reference that may have a publication date after the priority dateof this application. The disclosures of all patents, patentapplications, and publications cited herein are hereby incorporated byreference, to the extent that they provide exemplary, procedural orother details supplementary to those set forth herein.

1. A well bore servicing fluid comprising a thermally activatedviscosification composition comprising an ionic water-soluble,hydrophobically modified polymer; wherein the ionic water-soluble,hydrophobically modified polymer is: a copolymer of N-alkylacrylamidesand an ionic monomer; a copolymer of stearylacrylate and acrylic acid; aterpolymer of N-isopropylacrylamide, trimethyl acrylamidopropyl ammoniumiodide, and 3-dimethyl-(methacryloxyethyl) ammonium propane sulfonate; acopolymer of N-tertiarybutylacrylamide or N-isopropylacrylamide and2-acrylamide-2-methyl propane sulfonic acid;poly(ethyleneoxide)-block-poly(propyleneoxide)-block-poly(ethyleneoxide)grafted with polysodium acrylate; hydrophobically modified poly(sodiumacrylate); or copolymer of N-vinylcaprolactam and sodium acrylate; andwherein the copolymer of N-alkylacrylamides and an ionic monomerconsists of 60 to 0.1 mole percent hydrophilic monomers and 40 to 99.9mole percent hydrophobic monomers.
 2. The well bore servicing fluid ofclaim 1, wherein the servicing fluid further comprises a downholereleasable encapsulated salt.
 3. The well bore servicing fluid of claim2, wherein the encapsulated salt comprises an ammonium salt, a sodiumsalt, a potassium salt, or combinations thereof.
 4. The well boreservicing fluid of claim 2, wherein the encapsulated salt is capable ofreducing a temperature of the servicing fluid and thereby capable ofreducing a viscosity of the servicing fluid.
 5. The well bore servicingfluid of claim 1, wherein the servicing fluid further comprises anon-ionic surfactant.
 6. The well bore servicing fluid of claim 5wherein the non-ionic surfactant is an oligoethylene glycol monodecylether surfactant.
 7. The well bore servicing fluid of claim 1, whereinthe thermally activated viscosification composition comprises a linearpolymer.
 8. The well bore servicing fluid of claim 7, wherein the linearpolymer is capable of forming a physically crosslinked gel.
 9. The well,bore servicing fluid of claim 1, wherein the servicing fluid comprises acement slurry, a drilling fluid, a gravel packing fluid, a fracturingfluid, or combinations thereof.
 10. The well bore servicing fluid ofclaim 1, wherein the water-soluble, hydrophobically modified polymercomprises a hydrophobic substituent having from about 1 to about 22carbon atoms.
 11. The well bore servicing fluid of claim 1, wherein aviscosity of the servicing fluid is effective to suspend solids thereinwhen the servicing fluid is in the well bore.
 12. The well boreservicing fluid of claim 1, wherein a viscosity of the servicing fluidis effective to suspend drill cuttings therein when the servicing fluidis pumped from the subterranean formation to near the surface of theearth.
 13. The well bore servicing fluid of claim 1, wherein thethermally activated viscosification composition is capable of forming achemically crosslinked gel, a physically crosslinked gel, orcombinations thereof.
 14. The well bore servicing fluid of claim 1,wherein the thermally activated viscosification composition is capableof forming a thermally reversible gel.
 15. The well bore servicing fluidof claim 1, wherein an amount of the thermally activated viscosificationcomposition present in the servicing fluid ranges from about 0.1% toabout 5% by total weight of the servicing fluid.
 16. The well boreservicing fluid of claim 1, further comprising a proppant.